Out of center downhole tool

ABSTRACT

A tubular component configured to be interposed between parts of a drill string used with a cased wellbore. A lobe is supported on and projects from an outer surface of the tubular component. The lobe causes the tubular component to have a cross-sectional profile that is asymmetric relative to an axis of symmetry of the drill string. As the drill string and tubular component rotate, the lobe contacts debris within the wellbore. The lobe also causes the drill string to rotate eccentrically, helping to reduce friction between the drill string and wellbore and dislodge a stuck drill string.

SUMMARY

The present invention is directed to a system comprising a cased wellbore extending within an underground environment, and an elongate tubular drill string situated, at least in part, within the cased wellbore, the drill string having an axis of symmetry. The system further comprises a tubular component interposed between parts of the drill string within the cased wellbore, the component including a section having an enclosed cross-sectional profile that is asymmetric relative to the axis of symmetry of the drill string.

The present invention is also directed to a system comprising an elongate tubular drill string situated, at least in part, within an underground environment, the drill string having an axis of symmetry. The system further comprises a plurality of identical tubular components situated in a spaced-apart relationship. Each tubular component is interposed between parts of the drill string and includes a section having an enclosed cross-sectional profile that is asymmetric relative to the axis of symmetry of the drill string.

The present invention is further directed to a method of using a cased wellbore that extends within an underground environment. The method comprises the steps of assembling a drill string having an axis of symmetry such that a tubular component is interposed between parts of the drill string. The tubular component includes a section having an enclosed cross-sectional profile that is asymmetric relative to the axis of symmetry of the drill string. The method further comprises the steps of inserting the drill string and interposed tubular component into the cased wellbore and causing the drill string and interposed tubular component to rotate within the cased wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is an illustration of a well completion operation.

FIG. 2 is a perspective view of a first end of an out of center downhole tool.

FIG. 3 is a perspective view of a second end of the downhole tool shown in FIG. 2.

FIG. 4 is a side elevational view of the downhole tool shown in FIG. 2.

FIG. 5 is a cross-sectional view of the downhole tool shown in FIG. 4, taken along line A-A.

FIG. 6 is enlarged view of a section of the wellbore shown in FIG. 1.

FIG. 7 is a cross-sectional view of the wellbore shown in FIG. 6, taken along line D-D.

FIG. 8 is a cross-sectional view of the wellbore shown in FIG. 6, taken along line E-E.

FIG. 9 is a perspective view of a first end of another embodiment of an out of center downhole tool.

FIG. 10 is a perspective view of a second end of the downhole tool shown in FIG. 9.

FIG. 11 is a side elevational view of the downhole tool shown in FIG. 9.

FIG. 12 is a cross-sectional view of the downhole tool shown in FIG. 11, taken along line B-B.

DETAILED DESCRIPTION

Turning to FIG. 1, during oil and gas drilling operations, a wellbore 10 is drilled beneath a ground surface 12 and a casing 14 is installed within the wellbore 10. The wellbore 10 shown in FIG. 1 comprises a vertical section 16 that transitions into a horizontal section 18. A tubular work or drill string 20 is shown installed within the casing 14. The work string 20 is known in the art as “coiled tubing”. Coiled tubing is typically used in well completion or workover operations to lower tools into the wellbore 10. One or more tools may be included in a bottom hole assembly (BHA) 22 attached to a first end 24 of the work string 20. One or more tools may also be incorporated into the work string 20 that are in a spaced-relationship with the bottom hole assembly 22.

The work string 20 is a long metal pipe that is typically between one and four inches in diameter. A first portion 26 of the work string 20 is situated within the casing 14 and a second portion 28 is wound around an above-ground reel 30. A second end 32 of the work string 20 is supported on the reel 30. In operation, the work string 20 is unwound from the reel 30 and lowered into the casing 14 to the desired depth. An injector head 34 positioned at the ground surface 12 grips and thrusts the work string 20 into the wellbore 10. In alternative embodiments, the tubular work string 20 may comprise jointed pipe, instead of coiled tubing.

Continuing with FIG. 1, a milling tool 36 is attached to the front end of the bottom hole assembly 22. The milling tool 36 comprises a rotatable drill bit 38. The drill bit 38 is rotated by a downhole motor, such as a mud motor, included in the bottom hole assembly 22. The milling tool 36 is used to grind up tools or obstructions, such as large composite plugs or other equipment, abandoned within the wellbore 10 during drilling and fracturing operations. Once the obstruction is ground into small pieces, the pieces may be flushed from the casing 14 with pressurized fluid. The drill bit 38 is shown engaged with a frac plug 40 in FIG. 1, for example.

During operation, debris not flushed from the casing 14 may become trapped between the work string 20 and the walls of the casing 14. As the work string 20 travels farther down the wellbore 10, the string 20 may become lodged on debris, causing the string 20 to become stuck. Movement of the work string 20 may also be limited by the friction between the casing 14 and the work string 20 as the work string 20 travels farther down the wellbore 10.

The present disclosure describes a downhole tool 50, shown in FIGS. 2-5, configured to break up debris caught between the casing 14 and the work string 20. The tool 50 is also configured to dislodge a stuck work string 20, as well as alleviate friction between the work string 20 and the casing 14. As will be discussed in more detail herein, one or more of the tools 50 may be incorporated into the work string 20, as shown by the tools 50A, 50B, and 50C in FIG. 1.

Turning to FIGS. 2-5, the downhole tool 50 is tubular and comprises opposed first and second ends 52 and 54 interconnected by a central passage 56. The downhole tool 50 may be characterized as a tubular component 50. The first end 52 comprises external threads 58, and the second end 54 comprises internal threads 60. Each end 52 and 54 may attach to corresponding threads formed in sections of the work string 20. In alternative embodiments, the downhole tool 50 may be configured to be incorporated into the work string 20 by welding. In operation, the central passage 56 is in fluid communication with the rest of the work string 20.

Continuing with FIGS. 2-5, the downhole tool 50 further comprises a lobe 62 supported on an external surface 64 of the downhole tool 50. The lobe 62 may be attached to the external surface 64 using fasteners or welding. Alternatively, the lobe 62 may be formed as an integral piece of the downhole tool 50. The lobe 62 is preferably situated on the external surface 64 about mid-way between the ends 52 and 54, but it may be positioned closer to one of the ends 52 or 54, if desired.

The lobe 62 has a generally wedge shape and projects from the external surface 64. The lobe 62 comprises opposed upper and lower ends 66 and 68 joined by tapered sidewalls 70. The sidewalls 70 taper inwardly from the lower end 68 to the upper end 66 such that the lower end 68 is wider and longer than the upper end 66. The upper end 66 is flat or rounded, while the lower end 68 conforms to the shape of the external surface 64 of the downhole tool 50. The lobe 62 has a longitudinal axis 72 that is parallel to a longitudinal axis 73 of the tool 50, as shown in FIG. 3.

The lobe 62 may have a length that is between one-fourth to two-thirds of the length of the tool 50, it may have a height between one-tenth to three-fourths of the tool 50 diameter, and it may have a width between one-tenth to the full tool 50 diameter. The dimensions of the lobe 62 may vary, as desired, depending on the conditions of the wellbore at issue. The lobe 62 may be formed of the same metal as the downhole tool 50, such as steel. Alternatively, the lobe 62 may be formed from or comprise a more hardened and more wear resistant material than that of the downhole tool 50, such as tungsten carbide. For example, the lobe 62 may be sprayed with tungsten carbide or be heat treated. In further alternatives, the upper end 66 may be ridged, or patterned in any manner, to provide a non-planar, or varying height, surface that reduces overall friction resistance. Such design allows debris to pass through, or be stored in, the grooves or other voids produced by the varying height surface.

Turning to FIGS. 6-8, the work string 20 has an axis of symmetry 74, as shown in FIG. 7. The downhole tool 50 has a section having an enclosed cross-sectional profile 76 that is asymmetric relative to the axis of symmetry 74, as shown by a comparison of FIGS. 7 and 8. The cross-sectional profile 76 is considered enclosed because it does not have any free ends. The section of the downhole tool 50 having such enclosed cross-sectional profile comprises the lobe 62. In operation, as the work string 20 rotates, the lobe 62 contacts any debris surrounding the work string 20, helping to break the debris into smaller pieces or dislodge any stuck debris. Such debris is then flushed from the wellbore 10 with pressurized fluid.

Continuing with FIG. 1, the lobe 62 may also cause the work string 20 to rotate out-of-center or rotate eccentrically. Such rotation may cause the work string 20 to lift and fall as it rotates or engages the walls of the casing 14 or wellbore 10 as it rotates. Such motion causes the work string 20 to contact or crush debris situated between the work string 20 and the casing 14 or the wellbore 10. Such motion also helps break any friction between the work string 20 and the casing 14 or the wellbore 10 during operation, thereby helping to prevent the work string 20 from becoming stuck during operation. Further, such motion helps dislodge an already stuck work string 20.

Turning back to FIGS. 2-5, the downhole tool 50 does not have any moving parts and does not need to be activated by a drop ball to operate. Rather, the tool 50 rotates in response to rotation of the work string 20. The downhole tool 50 does not comprise any ports, other than the openings of the central passage 56 at the ends 52 and 54 of the tool 50. During operation, no fluid exits the sides of the tool 50, fluid only flows through the central passage 56. The downhole tool 50 is preferably solid, except for the central passage 56.

Turning back to FIG. 1, multiple downhole tools 50 may be incorporated into the work string 20. For example, three tools 50A, 50B, and 50C are shown interposed between parts of the work string 20 in FIG. 1. A first tool 50A may be positioned 100 feet upstream from the bottom hole assembly 22, or at least 90 feet from the first end 24 of the work string 20. A second tool 50B may be positioned 100 feet upstream from the first tool 50A, and a third tool 50C may be positioned 1,000 feet upstream from the second tool 50B. In alternative embodiments, more than three downhole tools 50 or less than three downhole tools 50 may be incorporated into the work string 20 and be spaced at any desired increments.

In other embodiments, the lobe 62 may be attached directly to an outer surface of the work string 20 or other tools or collars already incorporated into the work string 20. In such instance, the section of the work string 20 or other tool or collar carrying the lobe 62 may be considered the tubular component.

Turning to FIGS. 9-12, another embodiment of a downhole tool 100 is shown. The downhole tool 100 may be characterized as a tubular component 100. The downhole tool 100 is identical to the downhole tool 50, but it comprises another embodiment of a lobe 102. Since the tools 50 and 100 are identical, the features of the tool 100, other than the lobe 102, are given the same reference numbers as the downhole tool 50.

The lobe 102 has the shape of an elongate metal rod and is supported on the external surface 64 about mid-way between the ends 52 and 54. However, the lobe 102 may be positioned closer to one of the ends 52 and 54, if desired. The lobe 102 may be made from the same material as the lobe 62. The lobe 102 may be attached to the external surface 64 of the downhole tool 100 or may be formed as an integral piece of the tool 100. The lobe 102 has a longitudinal axis 104 that is parallel to the longitudinal axis 73 of the tool 100, as shown in FIG. 10. The lobe 102 may have a length between one-fourth and two-thirds a length of the tool 100, it may have a height between one-tenth to three-fourths of the tool 100 diameter, and it may have a width between one-tenth to the full tool 100 diameter. The dimensions of the lobe 102 may vary, as desired, depending on the conditions of the wellbore at issue.

The lobe 102 may be formed of the same metal as the downhole tool 100, such as steel. Alternatively, the lobe 102 may be formed from or comprise a more hardened and more wear resistant material than that of the downhole tool 100, such as tungsten carbide. For example, the lobe 102 may be sprayed with tungsten carbide or be heat treated. In further alternatives, lobe 102 may be ridged, or patterned in any manner, to provide a non-planar, or varying height, surface that reduces overall friction resistance. This allows debris to pass through, or be stored in, the grooves or other voids produced by the varying height surface.

Like the downhole tool 50, the downhole tool 100 has a section having an enclosed cross-sectional profile 106 that is asymmetric to the axis of symmetry 74 of the drill string 20, as shown by a comparison of FIGS. 7 and 12. The section comprises the lobe 102. The lobe 102 serves the same function as the lobe 62.

In other embodiments, the lobe 62 or 102 may have a different shape from that shown in FIGS. 2-5 and 9-12, as long as the lobe has an enclosed cross-sectional profile that is asymmetric to the work string's axis of symmetry 74. For example, the lobe itself may have an asymmetrical shape or may have grooves or other features formed therein. The lobe may further be configured such that is removable from the downhole tool 50 or 100 and/or other tubular component, if desired.

The various features and alternative details of construction of the apparatuses described herein for the practice of the present technology will readily occur to the skilled artisan in view of the foregoing discussion, and it is to be understood that even though numerous characteristics and advantages of various embodiments of the present technology have been set forth in the foregoing description, together with details of the structure and function of various embodiments of the technology, this detailed description is illustrative only, and changes may be made in detail, especially in matters of structure and arrangements of parts within the principles of the present technology to the full extent indicated by the broad general meaning of the terms in which the appended claims are expressed. 

1. A system, comprising: a cased wellbore extending within an underground environment; an elongate tubular drill string situated, at least in part, within the cased wellbore, the drill string having an axis of symmetry; and a tubular component interposed between parts of the drill string within the cased wellbore, the component including a section having an enclosed cross-sectional profile that is asymmetric relative to the axis of symmetry.
 2. The system of claim 1, in which the tubular component is configured to cause eccentric rotation of the drill string.
 3. The system of claim 1, in which the drill string has opposed first and second ends, the first end being situated within the cased wellbore; in which the drill string includes a region situated at least 90 feet from the first end; and in which the tubular component is interposed between parts of the drill string at the region.
 4. The system of claim 1, in which the section comprises a lobe projecting from an external surface of the tubular component.
 5. The system of claim 4, in which the lobe has a wedge shape.
 6. The system of claim 4, in which the tubular component has opposed first and second ends and in which the lobe is positioned at a mid-point between the first and second ends.
 7. The system of claim 4, in which a longitudinal axis of the lobe is parallel to a longitudinal axis of the tubular component.
 8. The system of claim 1, in which the tubular component comprises an external surface, and in which the tubular component does not comprise any parts that move relative to the external surface.
 9. The system of claim 1, in which no ports are formed in the tubular component except for a central fluid passage that interconnects opposed first and second ends of the tubular component.
 10. The system of claim 1, in which the tubular component is solid except for a central fluid passage that interconnects opposed first and second ends of the tubular component.
 11. A method of using the system of claim 1, the method comprising: causing the drill string and interposed tubular component to rotate within the cased wellbore.
 12. A system, comprising: an elongate tubular drill string situated, at least in part, within an underground environment, the drill string having an axis of symmetry; and a plurality of identical tubular components situated in a spaced-apart relationship, each tubular component interposed between parts of the drill string and including a section having an enclosed cross-sectional profile that is asymmetric relative to the axis of symmetry.
 13. The system of claim 12, in which the section comprises a lobe attached to an external surface of the tubular component.
 14. The system of claim 12, in which the drill string has opposed first and second ends and a first region situated at least 90 feet from the first end of the drill string; and in which a first one of the plurality of identical tubular components is interposed between parts of the drill string at the first region.
 15. The system of claim 14, in which the drill string has a second region situated at least 1,000 feet from the first end of the drill string; and in which a second one of the plurality of identical tubular components is interposed between parts of the drill string at the second region.
 16. The system of claim 15, in which the drill string has a third region situated at least 2,000 feet from the first end of the drill string; and in which a third one of the plurality of identical tubular components is interposed between parts of the drill string at the third region.
 17. A method of using the system of claim 12, the method comprising: causing the drill string and interposed tubular components to rotate within the cased wellbore.
 18. The system of claim 12, in which the drill string is situated within a cased wellbore.
 19. A method of using a cased wellbore that extends within an underground environment, comprising: assembling a drill string having an axis of symmetry such that a tubular component is interposed between parts of the drill string, the component including a section having an enclosed cross-sectional profile that is asymmetric relative to the axis of symmetry; inserting the drill string and interposed tubular component into the cased wellbore; and causing the drill string and interposed tubular component to rotate within the cased wellbore.
 20. The method of claim 19, in which the drill string has opposed first and second ends and a region that is at least 90 feet from the first end, in which the tubular component is interposed between parts of the drill string at the region.
 21. The method of claim 19, further comprising: causing the drill string to rotate eccentrically within the cased wellbore. 